- 

Identifying and Remediating 

High Water Production Problems in 

Basin-Centered Formations 

Final Report 

Reporting period: April 1, 2002 to September 30, 2005 

Prepared by: 

R. L. Billingsley 

December 2005 

DOE Award No. DE-FC26-02NT41437 

Submitting Organization: 

Advanced Resources International, Inc. 

4501 Fairfax Drive, Suite 910 

Arlington, Virginia 22203-1661 

Significant Subcontractors 

Maria Wood Henry

Henry GeoConsulting Services, Inc. 

863 W. Geddes Ave. 

Littleton, CO 80120 

Keith Jagiello, Ph.D.

Petro Data Integration, LLC 

8770 West Eden Drive 

Littleton CO 80127 

Leta K. Smith, Ph.D.

Consultant 

10154 Whiteside Lane 

Houston, TX 77043
Disclaimer 

This report was prepared as an account of work sponsored by an agency of the United 

States Government. Neither the United States Government nor any agency thereof, nor 

any of their employees, makes any warranty, express or implied, or assumes any legal 

liability or responsibility for the accuracy, completeness, or usefulness of any 

information, apparatus, product, or process disclosed, or represents that its use would not 

infringe privately owned rights. Reference herein to any specific commercial product, 

process, or service by trade name, trademark, manufacturer, or otherwise does not 

necessarily constitute or imply its endorsement, recommendation, or favoring by the 

United States Government or any agency thereof. The views and opinions of authors 

expressed herein do not necessarily state or reflect those of the United States Government 

or any agency thereof. 

Contract DE-FC26-02NT41437 December 2005 Final Report page i 
Abstract 

Through geochemical analyses of produced waters, petrophysics, and reservoir simulation we 

developed concepts and approaches for mitigating unwanted water production in tight gas 

reservoirs and for increasing recovery of gas resources presently considered noncommercial. 

Only new completion research (outside the scope of this study) will validate our hypothesis. 

The first task was assembling and interpreting a robust regional database of historical producedwater analyses to address the production of excessive water in basin-centered tight gas fields in 

the Greater Green (GGRB ) and Wind River basins (WRB), Wyoming. The database is 

supplemented with a sampling program in currently active areas. Interpretation of the regional 

water chemistry data indicates most produced waters reflect their original depositional 

environments and helps identify local anomalies related to basement faulting. 

After the assembly and evaluation phases of this project, we generated a working model of tight 

formation reservoir development, based on the regional nature and occurrence of the formation 

waters. Through an integrative approach to numerous existing reservoir concepts, we synthesized 

a generalized development scheme organized around reservoir confining stress cycles. This single 

overarching scheme accommodates a spectrum of outcomes from the GGRB and Wind River 

basins.

Burial and tectonic processes destroy much of the depositional intergranular fabric of the 

reservoir, generate gas, and create a rock volume marked by extremely low permeabilities to gas 

and fluids. Stress release associated with uplift regenerates reservoir permeability through the 

development of a penetrative grain bounding natural fracture fabric. Reservoir mineral 

composition, magnitude of the stress cycle and local tectonics govern the degree, scale and exact 

mechanism of permeability development. 

We applied the reservoir working model to an area of perceived anomalous water production. 

Detailed water analyses, seismic mapping, petrophysics, and reservoir simulation indicate a 

lithologic and structural component to excessive in situ water permeability. Higher formation 

water salinity was found to be a good pay indicator. Thus spontaneous potential (SP) and 

resistivity ratio approaches combined with accurate formation water resistivity (Rw) information 

may be underutilized tools. Reservoir simulation indicates significant infill potential in the 

demonstration area. Macro natural fracture permeability was determined to be a key element 

affecting both gas and water production. 

Using the reservoir characterization results, we generated strategies for avoidance and mitigation 

of unwanted water production in the field. These strategies include (1) more selective perforation 

by improved pay determination, (2) using seismic attributes to avoid small-scale fault zones, and 

(3) utilizing detailed subsurface information to deliberately target optimally located small scale 

fault zones high in the reservoir gas column. Tapping into the existing natural fracture network 

represents opportunity for generating dynamic value. 

Recognizing the crucial role of stress release in the natural generation of permeability within

tight reservoirs raises the possibility of manmade generation of permeability through local 

confining stress release. To the extent that relative permeabilities prevent gas and water 

movement in the deep subsurface a reduction in stress around a wellbore has the potential to 

increase the relative permeability conditions, allowing gas to flow. For this reason, future 

research into cavitation completion methods for deep geopressured reservoirs is recommended. 

Contract DE-FC26-02NT41437 December 2005 Final Report page ii 
Contract DE-FC26-02NT41437 December 2005 Final Report page iii 

Table of Contents 

Disclaimer................................................................................................................. i

Abstract.................................................................................................................... ii

List of Graphical Materials ...................................................................................... vi

Acknowledgements................................................................................................viii

INTRODUCTION...............................................................................................................1

EXECUTIVE SUMMARY ..................................................................................................2

EXPERIMENTAL..............................................................................................................4

RESULTS AND DISCUSSION .........................................................................................5

I. Digital Database ........................................................................................................ 5

Format and Structure...............................................................................................6

II. Digital Map Atlas ...................................................................................................... 8

III. Produced Water Geochemistry Evaluation ............................................................. 9

The Process of Geochemical Analyses...................................................................9

Assertions..............................................................................................................11

Depositional Environment of Host Rock ........................................................................ 11

Assessing Anomalies Against the Base ........................................................................ 13

IV. Working Model for Reservoir Development .......................................................... 14

Background............................................................................................................14

Basin-Centered Gas Paradigm...................................................................................... 15

Working Concept Premises ........................................................................................... 16

Two-Phase Tight Gas Reservoir Development .....................................................16

Introduction ............................................................................................................... 16

Basin Scale Processes..........................................................................................18

Stages in tight gas reservoir development..................................................................... 18

Phase I (Burial) .............................................................................................................. 19

Phase II (Basin Uplift) .................................................................................................... 20

Summary ...............................................................................................................22

V. Wild Rose Field Demonstration ............................................................................. 23

Overview................................................................................................................23

Site Selection ................................................................................................................. 23

The Geologic Characterization of the Field Demonstration Area .................................. 23

Petrophysical Reservoir Characterization...................................................................... 32
Contract DE-FC26-02NT41437 December 2005 Final Report page iv 

Rw Calibration................................................................................................................ 33

The Reservoir Simulation ......................................................................................37

Matching Procedures ..................................................................................................... 37

Field Match Results ....................................................................................................... 39

Forecast Model .............................................................................................................. 43

Analysis .................................................................................................................46

Trends and Context ....................................................................................................... 47

Salinity Trends .......................................................................................................... 47

Basement Structural Trends..................................................................................... 48

Structural Modeling................................................................................................... 49

Vertical Mineralogical Trend ..................................................................................... 50

Production Validation................................................................................................ 50

Water Remediation Strategies....................................................................................... 51

Avoidance Strategy for Small Scale Faulting ........................................................... 52

Capture Strategy for Small Scale Faulting ............................................................... 53

CONCLUSION................................................................................................................54

Digital Database and Atlas ....................................................................................54

Applications ...........................................................................................................54

1. Secondary Porosity Prediction................................................................................... 54

2. Formation Evaluation................................................................................................. 54

3. Development Strategies............................................................................................. 55

Perforation Strategy.................................................................................................. 55

Avoidance Strategy for Small Scale Faulting ........................................................... 55

Capture Strategy for Small-Scale Faulting ............................................................... 55

Future Research....................................................................................................56

REFERENCES................................................................................................................57

ACRONYMS AND ABBREVIATIONS............................................................................97

ACRONYMS AND ABBREVIATIONS............................................................................97

APPENDICES...............................................................................................................102

A. Database.............................................................................................................. 102

• Database_Readme................................................................................................ 102

• Database_Access.................................................................................................. 102

• Database_CSV ...................................................................................................... 102

• Database_DBF ...................................................................................................... 102

• Database_XLS....................................................................................................... 102
Contract DE-FC26-02NT41437 December 2005 Final Report page v 

B. Atlas of Maps ....................................................................................................... 102

• ArcReader Install ................................................................................................... 102

• Digital Atlas ............................................................................................................ 102

C. Produced Water Geochemistry............................................................................ 102

D. Working Model for Reservoir Development ......................................................... 102

E. Wild Rose Field Petrophysics .............................................................................. 102

F. Wild Rose Reservoir Simulation........................................................................... 102
Contract DE-FC26-02NT41437 December 2005 Final Report page vi 

List of Graphical Materials 

Figures 

Fig. I-1 Areal distribution of water sample locations contained in the database........... 6

Fig. III-1. Stratigraphic column identifying major units & their ages ........................... 10

Fig. III-2. Salinity vs., depth for Lance, Almond and Frontier...................................... 11

Fig. IV-5. Williams Fork fm Southern Piceance basic example.................................. 15

Fig. IV-6. Burial history central Washakie basin......................................................... 18

Fig. IV-7. The working model ..................................................................................... 19

Fig. IV-8. Conceptual grain expansion & contraction ................................................. 20

Fig. IV-9. Influence of lateral stress............................................................................ 21

Fig. V-1. Wild Rose Field demonstration location map .............................................. 23

Fig. V-2. Stratigraphic column for Upper Cretaceous in Washakie basin, 

Wyoming..................................................................................................... 24

Fig. V-3. Wild Rose type log....................................................................................... 25

Fig. V-4. Local Wild Rose field index map.................................................................. 26

Fig. V-5. Flow unit and stratigraphic pick relationships .............................................. 27

Fig. V-6. Top Almond subsea structure from 3D seismic and wells ........................... 28

Fig. V-7 Northwest-southeast seismic time section.................................................... 29

Fig. V-8. Paleozoic Depth Structure from 3D seismic ................................................ 30

Fig. V-9. Wireframe illustration of deep Paleozoic fault system ................................. 31

Fig. V-10. Produced water Rw map of Wild Rose field demonstration area............... 33

Fig. V-11. Pickett plot gas zone – Rw =0.46 @ 68F .................................................. 34

Fig. V-12. Inferred SP-GWC structure map................................................................ 35

Fig. V-13. Cross-section from east to west along northern portion of model grid....... 37

Fig. V-14. Initial to final gas pressure arrays (layer 15) depicting some edge 

effects & showing relative depletion for inter-grid wells.............................. 40

Fig. V-15. Final field-wide cumulative gas & water production................................... 41

Fig. V-17. Final layer 15 forecast permeability grid .................................................... 43

Fig. V-18. Gas rate (A) & cumulative gas (B) forecasts for 155 wells, compared 

to forecasting pre-existing 76 wells ............................................................ 45

Fig. V-19. Four-variable plot of Wild Rose reservoir attributes................................... 46

Fig. V-21. Wild Rose field—first year water production.............................................. 48

Fig. V-22. Projected Laramide shear stresses at Almond level.................................. 49
Contract DE-FC26-02NT41437 December 2005 Final Report page vii 

Tables 

Table III-1. Range of TDS from water analyses by formation..................................... 12

Table III-2. Range of TDS by salinity population ........................................................ 12

Table V-1. Initial gas & water in place for 23 model layers ........................................ 38

Table V-2. By-layer voidage & cumulative gas recovered in field thru 

October 2003.............................................................................................. 39

Table V-3. Water-gas ratios for fluid gas influx at each of 9 perforation 

sets............................................................................................................. 50
Contract DE-FC26-02NT41437 December 2005 Final Report page viii 

Acknowledgements 

Advanced Resources International, Inc. would like to acknowledge the National Energy 

Technology Laboratory (NETL), Morgantown, WV, for their role as lead funding agency 

together with the following companies and other governmental groups who contributed data, 

sampling opportunities or discussion: BP America, Schlumberger, Bill Barrett Corp., Anadarko 

Petroleum Corp., Devon, Shell Western E&P, Stone, Ultra Petroleum, USGS, and Wyoming Oil 

and Gas Commission. 

We would also like to thank the following individuals for their interpretive efforts or insightful 

discussion and comments; Vello Kuuskraa, George Koperna, Maria Fokin, Paul Ozanich, Marty 

Williams, John Forster, and Tim Schowalter. David Sears provided database coaching and 

processing support. Diane Suchomel and Dianne Finch-Smith deserve special recognition for 

their tireless efforts collecting data, sampling, editing and keeping us organized. 
Contract DE-FC26-02NT41437 December 2005 Final Report page ix 
 

INTRODUCTION 

Advanced Resources International Inc. (ARI), with support from the U.S. Department of 

Energy, conducted a research program (DE-FC-02NT41437) to characterize the nature, 

distribution and flow paths of moveable fluids in the subsurface of the Greater Green 

River basin (GGRB) and Wind River basin (WRB). The project goals were to improve 

resource characterization, develop water remediation strategies and enhance gas 

recoveries in these resource-rich basins. 

Specific project objectives include the following tasks: 

• Build a digital water chemistry database and construct key maps using the data. 

• Compile a digital atlas of maps that increases the usability of the database.

• Conduct an in-depth evaluation of produced water geochemistry that includes 

interpretation as well as application to the practical aspects of the project 

objectives 

• Develop a working model for movement of water and gas through low 

permeability basins (based on the geochemical evaluation). 

• Conduct a field demonstration for an area with known water production problems 

(to test the working model). 

• Transfer the technology to industry through a demonstrated conceptual model 

The results and discussion summarize the project. The bulk of the text, figures and data 

are included as appendices. This report is organized as follows: 

I. Digital Database (Appendix A) 

II. Digital Map Atlas (Appendix B) 

III. Produced Water Geochemistry Evaluation (Appendix C) 

IV. Working Model for Reservoir Development (Appendix D) 

V. Wild Rose Field Demonstration (Appendix E: Petrophysics) and (Appendix F: 

Simulation)

Contract DE-FC26-02NT41437 December 2005 Final Report page 1 
 

EXECUTIVE SUMMARY 

Advanced Resources International Inc. (ARI), with support from the U.S. Department of 

Energy, conducted a research program (DE-FC-02NT41437) to characterize the nature, 

distribution and flow paths of moveable fluids in the subsurface of the Greater Green 

River basin (GGRB) and Wind River basin (WRB). The project goals were to improve 

resource characterization, develop water remediation strategies and boost gas recoveries 

in these resource-rich basins. 

Specific project objectives included the following tasks: 

• Build a digital water chemistry database. 

• Compile a digital atlas of maps that increases the usability of the database. 

• Conduct an in-depth evaluation of produced water geochemistry that includes 

interpretation as well as application to the practical aspects of the project 

objectives. 

• Develop a working model for movement of water and gas through low 

permeability basins (based on the geochemical evaluation). 

• Conduct a field demonstration in an area with known water production problems. 

• Transfer the technology to industry. 

The results of this project provide the produced water chemistry backdrop, together with 

concepts and tools to reduce unwanted water production in tight gas reservoirs. The 

concepts and approaches generated also offer potential for the development of 

completion technologies to enhance permeability within tight reservoirs and achieve 

commercial production rates. 

A large database of historical produced water analyses, supplemented with a targeted 

sampling program, was assembled and interpreted to address the production of excessive 

water in basin-centered tight formation gas fields of the Greater Green and Wind River 

Basins, Wyoming. In excess of 16,000 historical chemical component and isotopic 

analyses from government, academic and industry sources were winnowed to produce a 

geographically referenced database of nearly 3,700 discreet formation tests. The analyses 

were screened for analytical validity and merged with perforation data and other support 

information (as available) to create a composite georeferenced water chemistry resource 

to support exploration and production activities across the GGRB and WRB. 

A digital atlas showing the distribution of the data and some specific analyses has been 

constructed using Arc Reader and is contained in Appendix B. The digital atlas has query 

and limited mapping capability for users without ready access to Geographic Information 

Systems (GIS) software. GIS techniques were used extensively in the project. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 2 
 

Regional evaluation of chemical and isotopic analyses indicates little mass movement of 

waters in the subsurface. Depositional environment is the chief influence on the 

composition of intra formation waters. Localized vertical movement of water along 

basement fault zones appears as more restricted anomalies in contrast to regional 

compositional variability. Both regional and local knowledge is required to successfully 

utilize water chemistry as an exploration or development tool. Public availability of the 

extensive database constructed as a result of this project will supplement the use of water 

chemistry at the field scale to increase gas production. 

A working model of tight formation reservoir development was synthesized using the 

results of the assembly and evaluation phases. An integrative approach was used to 

assemble numerous existing reservoir concepts into a generalized development scheme 

organized around reservoir confining stress cycles. Within this scheme, burial and 

tectonic processes destroy much of the depositional intergranular fabric of the reservoir, 

generate gas and create a rock volume marked by low permeabilities to gas and fluids. 

Stress release associated with uplift regenerates reservoir permeability through the 

development of a penetrative grain bounding natural fracture fabric. Reservoir mineral 

composition, magnitude of the stress cycle and local tectonics govern the degree, scale 

and exact mechanism of permeability development. Recognition of the primary role of

stress release in generation of naturally occurring reservoir permeability creates the 

opportunity to replicate the process artificially. Local permeability enhancement induced 

by some alternative stress reducing completion methodology could change the local gaswater relative permeability conditions and potentially allow gas to flow into the well. 

The working reservoir model was demonstrated in an area of anomalous water 

production. Detailed water analyses, seismic mapping, petrophysics and reservoir 

simulation indicate a lithologic and structural component to excessive in situ water 

permeability. Reservoir simulation indicates significant infill potential in the 

demonstration area. We found higher formation water salinity to be a pay indicator. 

Spontaneous potential (SP) and resistivity ratio approaches combined with accurate 

formation water resistivity (Rw) information are tools that can be utilized for improved 

pay recognition. We found macro natural fracture permeability to be a key element 

affecting both gas and water production. The results of the field study were used to 

generate strategies for avoidance or mitigation of excessive water production. 

Strategies developed to reduce unwanted water production in the field area include 1) 

more selective perforation through improved pay determination 2) use of seismic 

attributes to avoid small-scale fault zones and 3) capture of dynamic value through the 

use of infill drilling information to deliberately target optimally located small scale faults 

zones high in the reservoir gas column. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 3 
 

EXPERIMENTAL 

Work performed during this project conformed to generally accepted principles of 

petroleum geology and geochemistry. No laboratories were operated directly by ARI 

during the performance of this project. Laboratories used as part of this study are 

documented in Appendix C. The analytical vendors in accordance with applicable local 

and federal standards destroyed all samples collected during this project. 

Specific laboratory or interpretation techniques are referenced in the applicable 

appendices as follows: 

Geochemistry .........................Appendix C 

Petrophysics...........................Appendix E 

Reservoir Simulation .............Appendix F 

The following specific trademarked commercial software packages were used during the 

interpretive or documentation phases of this project: 

Petra, PetraseisTM (Geoplus Inc.) 

ArcCatalogTM, ArcMapTM, ArcPublisherTM, Spatial AnalystTM (ESRI, Inc) 

Microsoft Office Suite (Microsoft Corporation) 

Surfer 8TM, Grapher 5TM (Golden Software, Inc.) 

Canvas 8TM and Canvas 9TM (ACD Systems, Inc) 

Comet 3TM (Advanced Resources International, Inc.) 

The following non-commercial research software programs were used: 

NextGenTM (ARI, Inc) 

Poly3DTM (1993 Stanford University, Thomas) 

FracGenTM (discrete fracture network modeling, NETL) 

The majority of the project work was performed at ARI offices in Denver, CO. The 

reservoir simulation was performed at ARI offices in Arlington, VA. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 4 
 

RESULTS AND DISCUSSION 

I. Digital Database 

Accurate information regarding the composition of waters trapped in the interstices of

petroleum reservoirs is crucial to effective formation evaluation and resource estimation. 

Eight decades of oil and gas exploration in the Greater Green (GGRB) and Wind River 

Basins has resulted in a large volume of valuable produced water chemical analyses 

collected during formation evaluation, workover and water disposal operations. The 

preponderance of historical water composition data is the result of thousands of nonrecurring opportunities and is impossible to recreate. 

A primary objective of this project was to make available the abundant resource 

(spanning decades) of existing analytical data on produced water composition. Thus the 

first step in this project was to collect data from governmental entities, operators, 

abandoned files, and previous studies. It was then digitized as necessary and compiled 

into a digital database. 

The result of this collection effort was a comprehensive body of data, but one with 

considerable overlap and duplication. The next step was to use structured query language 

(SQL) queries to eliminate duplicate analyses and data with poor quality or otherwise 

erroneous aspects. Then, the location identification data was screened to 

1. Ensure that reported location data and American Petroleum Institute (API) 

numbers were correct to the fullest extent possible. Some otherwise valid data 

failed this final screening. 

2. Match as much high quality compositional data to valid API and location data 

as possible. In some cases this required examining the original location 

surveys. 

The final database was spot checked against randomly selected raw input data to ensure 

the integrity of the compilation process. 

The final product is a highly usable digital database of nearly 8,000 water analysis results 

from over 3,200 wells (fig. I-1). It spans nearly eight decades of exploration and 

production activity across two states (Wyoming and Colorado) and numerous productive 

basins including the strategically important Greater Green and Wind River Basin areas. 

Compilation of this data into a single database, with removal of duplicate and invalid 

analyses, opens the data to access by a broad audience of users with interests in resource 

assessment, formation evaluation, prospect generation and exploitation of tight formation 

gas.

Contract DE-FC26-02NT41437 December 2005 Final Report page 5 
 

Fig. I-1 Areal distribution of water sample locations contained in the database 

The database contains the results of routine chemical analyses performed on fluids 

produced during all phases of petroleum wellbore operations. The source and sampling 

method of the individual water samples is included where reported. Fluid sample 

analyses from drill stem test recoveries, as well as completion, workover, and production 

operations are represented. 

As a result, there is a wide range of applications for the data depending on the specific 

purposes of the user. 

Format and Structure 

The digital database format facilitates the effective use of the data by professionals 

working to increase gas production from these areas. The database is available in native 

AccessTM format as well as spreadsheet, text and DbaseTM formats, making possible 

immediate utilization in Geographic Information Systems (GIS) or other workstation 

systems. Details of the data quality screening criteria and final database structure are 

included in the Read me file located with the database in Appendix A. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 6 
 

The database structure was designed to support use of stable and radiogenic isotope 

technology in the interpretive process. Produced waters from eighty-eight currently 

producing wells in four separate areas (Waltman/Cave Gulch fields (WRB), Pinedale, 

Table Rock and Wild Rose fields (GGRB) were sampled for routine and isotopic 

characterization as part of this study. 

Although the analyses were screened for validity, formation tops and other data were 

assumed valid as reported by operators. Local lithostratigraphic and formation names 

were consolidated into broad groupings for mapping purposes. Those group names are 

included in the ‘Revised Formation’ database field. 

Consolidation of these data into an organized, accessible digital format enables 

immediate use of an irreplaceable body of knowledge accumulated as a result of literally 

thousands of non-recurring opportunities. Acquired at enormous expense over decades of 

exploration and production activity, this information, now accessible, will prove an 

invaluable resource in meeting the challenge of increasing available domestic energy 

resources. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 7 
 

II. Digital Map Atlas 

Our primary purpose in creating this digital atlas of maps was to increase the usability of

the database with a high-level tool for exploring it geographically. 

A principal value of a sizeable geographically-controlled digital database is the ability to 

identify large-scale regional variations in numerical data. This is particularly important 

for establishing a regional context when interpreting smaller prospect or field scale data 

sets. A digital atlas of maps displaying data distribution and several attributes potentially 

of interest to users is presented as Appendix B. 

Map layers have been constructed using common queries likely to be of interest to the 

high level user exploring data distribution. These include layers of data distribution by 

quality, revised formation, sample and analysis types. 

These maps are constructed in ArcmapTM (ESRI) and electronically published in 

ArcpublisherTM (ESRI). A copy of the current ArcReaderTM (Windows version, ESRI) 

package is included in Appendix. B. The software package is freely available by 

download from the web link: http://www.esri.com/software/arcgis/arcreader/index.html. 

Versions for Linux and Solaris operating systems are also available from this site. Refer 

to the ESRI website for hardware requirements, compatibility, and installation 

information. 

ArcReaderTM offers the ability to zoom and pan at the discretion of the user. Crude state 

and field outlines have been included for general reference. It includes public land survey 

grids to the section level. Users without direct access to GIS software can still use 

ArcReaderTM with some query and data export limitations. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 8 
 

III. Produced Water Geochemistry Evaluation 

Compiling a digital database of existing data and optimizing its accessibility with a 

digital map atlas laid were pre-cursors to the next phase of this project—conducting an 

in-depth evaluation of produced water geochemistry. The evaluation included 

interpretation as well as application to the practical aspects of the project objectives. This 

section is a high-level discussion of the results of the geochemical evaluation. Appendix 

C contains a detailed discussion of the analyses and interpretations. 

The Process of Geochemical Analyses 

First, aggregate produced water composition database were analyzed to establish regional 

trends and demonstrate potential uses for water chemistry as a tool to identify and 

remediate production of unwanted water. Geochemical interpretations were based on 

high-graded regional subsets and local samples collected as part of this project. Fig. I-1 is 

an index map showing general distribution of the data, which includes historical sample 

distribution and locations sampled and analyzed. 

Then, new samples were collected specifically for the geochemical water evaluation. 

Data cluster of samples were chosen from areas known for their anomalous character or 

high-profile development activities. These areas were Table Rock, Waltman/Cave Gulch, 

Pinedale and Wild Rose Fields (fig. I-1). Appendix B includes a detailed discussion of 

each area. Fig. III-1 is a generalized stratigraphic column identifying the major units 

sampled and their geologic ages. 

Finally, we performed three types of analyses on the formation water samples: 

1. Major and minor elements 

2. Stable isotopes (oxygen and hydrogen) 

3. Strontium radiogenic isotopes 

Contract DE-FC26-02NT41437 December 2005 Final Report page 9 
 

Fig. III-1. Stratigraphic column identifying major units & their ages 

Contract DE-FC26-02NT41437 December 2005 Final Report page 10 
 

Assertions 

From our analysis of formation waters produced from wells in the core study areas of

Greater Green (GGRB) and Wind River Basin we assert that there is no large-scale fluid 

movement. Instead there are smaller areas of water moving along faults and other breaks 

in the vertical continuity of the basin fill, more specifically: 

Depositional Environment of Host Rock 

The main control on formation water chemistry is the original depositional environment 

of the host rock. The following evidence supports this assertion: 

• There is little to no relationship between salinity of produced water and the depth 

of recovery for the three main producing horizons: Lance, Mesaverde, and 

Frontier formations (fig. III-2) 

Fig. III-2. Salinity vs., depth for Lance, Almond and Frontier (Enlarged in Appendix C-20) 

Contract DE-FC26-02NT41437 December 2005 Final Report page 11 
 

• The Frontier and Mesaverde formations are generally more saline, i.e., they 

exhibit wider ranges of salinity than the Lance formation waters. This is 

consistent with the marine affinities of the Frontier and the Mesaverde formations 

whereas the Lance is considered non-marine in origin and shows a fresher average 

salinity with less range (Table III-1).

Table III-1. Range of TDS from water analyses by formation 

Formation Range

Frontier 1,500 and 42,000 ppm 

Almond 1,700 and 50,000 ppm 

Lance 600 and 33,000 ppm 

Both the Frontier and Mesaverde formations, in general, represent retrograde 

transgressive sequences, and in the study area are overlain with thick sequences of 

marine shale. 

Thus, those formations deposited in marine environments produce water that 

tends to have higher total dissolved solids (TDS), has chloride as its dominant 

anion, and whose deuterium isotopes are less negative as compared to formations 

deposited in non-marine environments. Those deposited in non-marine 

environments tend to produce water that is fresher, has bicarbonate as the 

dominant anion, and has deuterium isotopes that are more negative (Table III-1). 

The overall lower TDS of the Lance formation, both in the average and the range, 

is in keeping with its non-marine origin as compared to the marine Frontier

formation. 

• Where the Almond formation can be divided into upper and lower units, two 

distinct salinity populations are present. The Upper Almond, of marine origin, 

shows a wider range of TDS and a higher average TDS than the Lower Almond, 

which is predominantly of non-marine origin (Table III-2). 

Table III-2. Range of TDS by salinity population 

Salinity Populations Range 

Upper Almond 19,000 ppm 

Lower Almond 13,000 ppm 

Lance 9,000 ppm

Contract DE-FC26-02NT41437 December 2005 Final Report page 12 
 

The overall lower TDS of the Lance formation, both in the average and the range, 

is in keeping with its non-marine origin as compared to the marine Frontier

formation. 

Assessing Anomalies Against the Base 

Second Assertion: Local salinities, TDS values or isotope signatures, at extreme variance 

to regional formation or facies norms, represent vertical disruption of the basin fill and 

fluid or charge transport along permeability conduits associated with basement faulting. 

• Water samples collected along major lineaments or areas of high surface 

lineament density exhibit anomalous local values of salinity, TDS or isotopes in 

contrast to regional means for these same values. See Appendix C for a complete 

discourse on this significant assertion. 

• Water samples collected along major lineaments or areas of high surface 

lineament density exhibit anomalous local values of salinity, TDS or isotopes in 

contrast to regional means for these same values. This phenomenon is exhibited in 

fig. V-10, and Appendix C figs. C-32 and C-33 where individual attributes such 

as Rw, isotopes, and saturation indices exhibit local departures from overall 

geographic trends established by relatively higher density sampling. See 

Appendix C for a complete discourse on this significant assertion. 

• Some local and regional geologic problems can best be understood through 

interpretation of chemical and isotopic compositions of produced formation 

waters. 

Geochemical attributes afford significant potential for impact on near and long-term

exploration and development activities when properly sampled, analyzed, and interpreted.

A geodatabase is a powerful approach as it enables rapid evaluation of local analytical 

results and identification of anomalies within a regional geologic context. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 13 
 

IV. Working Model for Reservoir Development 

Background 

Data from the produced water database, geochemistry, field demonstration phases of this 

project, as well as public information sources were used to develop a working model for 

movement of gas and water through low permeability basins within a framework of basin 

history. 

The nature and occurrence of moveable water, geomechanics, stratigraphy, and reservoir 

engineering guided our conceptualization of tight gas reservoir development. Knowledge 

of lithology, stratigraphy and basin history (particularly uplift) in the development of 

these enigmatic reservoirs was referenced extensively. 

The results of the compositional study of the produced waters were applied, together with 

the authors’ operating and research experience, to formulate working hypotheses about 

the origins of the produced waters. These hypotheses laid the foundation of our working 

model for strategies to avoid and/or remediate unwanted water production. The working 

model ensured consistency as our hypotheses were tested, refined, and ultimately 

incorporated into a conceptual model for water in tight gas reservoirs. 

Iterations of the working model were presented at the AAPG Hedberg Tight Formation 

Gas Symposium in Vail, CO (April 2005) and at the 2005 AAPG national convention in 

Calgary, Alberta (June 2005). The Hedberg poster and the AAPG slides are included in 

Appendix D, which also includes an in-depth discussion of the reservoir development 

model. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 14 
 

Basin-Centered Gas Paradigm 

The basin-centered gas paradigm postulates the presence of a large volume of gascharged sediments at near irreducible water saturation. Located in a down dip position 

relative to an up dip water saturated volume it is depicted in fig. IV-5. Such units 

generally yield gas shows when drilled but are projected to have very low permeability to 

water. 

Cross-section showing relative position of gas-saturated, transition, and water-saturated zones 

Fig. IV-5. Williams Fork fm Southern Piceance basic example 

The United States Geological Survey (USGS) considers these to be continuous class 

hydrocarbon deposits. Since the early phases of basin-centered gas exploitation, it was 

commonly believed industry-wide that the only significant unknown variable was 

permeability—that exploitation of these widespread resources could be pursued on a 

statistical basis. 

As development continues, it’s become clear that this concept was limited by the data 

available. Encountering excess (moveable) water is a far more frequent outcome in recent 

years as tight gas development operations intensify. The rising risk of unwanted water 

production has prompted efforts (2004, Shanley and others) to re-evaluate the basincentered paradigm. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 15 
 

Working Concept Premises 

A major given for this study was a basin with a mixed fill of coarse and fine-grained 

clastic sediments with sufficient source, heat and reservoir to provide moderate gas 

charge, reservoirs and seals. We incorporated the following from our study of subsurface 

waters, previous work by others, and experience to frame our conceptualization of tight 

gas reservoir development within such a basin. 

1. Produced water compositions generally reflect host rock environments of 

deposition. (2004 Henry and Billingsley). 

2. Areas of faulting and vertical transport may be indicated by anomalous chemical 

and/or isotopic compositions as measured against background regional trends 

(2004 Henry and Billingsley). 

3. One study of water chemistry suggests gas and water production from coals. 

(1998 Smith and Surdam). 

4. Gravity segregation of some gas accumulations in the Greater Green River basin 

is well-documented (2004 Shanley, et al). 

5. The impact of stress dependency on relative permeability is mathematically 

corroborated by Ostensen (1983), Byrnes (1997) and Shanley (2004). 

6. The significant role of temperature in generation of subsurface stress as 

established by Warpinski (1989), Engelder (1985), and others. 

7. The role of poro-elastic effects during uplift of gas charged sediments as 

documented by Katahara and Corrigan (2002). 

8. Last, but not least we took into account that: 

- The ability of water to flow in the deep subsurface is more restricted than gas; 

water is more easily characterized chemically than gas. 

- Most significant large-scale tight gas basins have undergone significant uplift 

after gas generation. 

Two-Phase Tight Gas Reservoir Development 

Introduction

Bourne (2001) observed that natural fracture development, particularly type, was 

influenced by whether net mean confining stress was increasing or decreasing when 

failure occurred. He used a modified Griffith –Coulomb failure criterion to show that 

shear failure in rocks would most likely occur when net mean stress was increasing, and 

that extensional failure would most likely occur when the net mean stress was decreasing 

(commonly during uplift). 

Contract DE-FC26-02NT41437 December 2005 Final Report page 16 
 

Widespread extensional failure during uplift can be predicted using poroelastic (1993 

Higgs and Bradley) or viscoelastic (1989 Warpinski) methods. Engelder (1990) also 

demonstrated the potential for widespread failure during uplift using thermoelastic 

methods (the fixed-grips Griffith energy balance approach). Regardless of the method 

used—poroelastic, viscoelastic and thermoelastic—the potential for widespread 

extensional failure can be shown to occur during periods of falling mean confining stress. 

The overall direction of our investigation was influenced by the convergence of these 

methods. 

Other factors in tight gas reservoir development parallel the two-stage increase-decrease 

pattern. It is generally accepted that hydrocarbon generation occurs during increasing 

burial and slows or ceases during uplift. The progressive mechanical and chemical 

destruction of original porosity and permeability is often referred to as “burial” 

diagenesis. The generation of abnormal pressures at depth is envisioned as a consequence 

of increasing burial. The response of the basin fill to increasing burial (increasing stress) 

is different than it is to uplift. 

A major common theme in the geologic history of the Rocky Mountain tight gas basins is 

a late stage uplift event. Fig. IV-6 is a representative example from the Washakie basin

(1994 MacGowan et al). Cycles of energy input (increasing temperature and confining 

stress), and release (decreasing temperature and confining stress) control mechanical 

strains, and chemical diagenesis of sediments through time. This common sequence of

events across several basins (not necessarily in severity or timing) prompted us to use 

frame the burial-uplift cycle and its impact on the basin fill as an organizational 

framework for our working model. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 17 
 

Subsidence Uplift 

Although depth of burial, amounts of uplift and timing vary between basins, the Rocky Mountain 

tight gas basins share a common history of subsidence followed by later uplift. Modified after 

MacGowan et al, 1994. 

Fig. IV-6. Burial history central Washakie basin 

Basin Scale Processes 

Stages in tight gas reservoir development 

Stages in tight gas reservoir development (fig. IV-7) can be organized into two phases, 

each defined by the direction of net mean stress change over time: Phase I is a time of net 

mean stress increase and Phase II is a time of net mean stress decrease. Reservoir 

development is also highly influenced by mechanical properties of the reservoir, 

mineralogy (provenance), proportions of mineralogies present in different facies and 

diagenesis 

Contract DE-FC26-02NT41437 December 2005 Final Report page 18 
 

Fig. IV-7. The working model 

Phase I (Burial) 

Phase 1 of tight gas reservoir development begins with the deposition of the reservoir/ 

source system and ends with the system at maximum temperature and burial depth. 

During Phase I the mechanical and chemical diagenetic effects of burial destroy a 

majority of the reservoir’s primary porosity and permeability. Hydrocarbon generation

occurs during the later stages of Phase I and peaks near maximum depth of burial. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 19 
 

At the end of Phase I the potential reservoir has reached its minimum porosity and 

permeability. It may be locked in the “permeability jail,” which Byrnes defined as 

conditions of porosity, permeability and relative saturation in a two-phase system such 

that neither phase present (gas or water for example) has significant permeability (2004 

oral comm, Shanley). Permeability jail is a useful concept to mark the transition between 

developmental Phases I and II. 

Phase II (Basin Uplift) 

The onset of basin uplift marks the beginning of Phase II. Rock strength declines with net 

confining stress. Effective porosity and permeability increase (particularly in quartz rich

sediments) as microfractures develop along the margins of shrinking quartz grains 

(tabular pore throats) and connect previously isolated primary porosity. Fig. IV-8 is a 

schematic illustration of the grain expansion and contraction process. 

Fig. IV-8. Conceptual grain expansion & contraction 

During Phase II of the developmental cycle, net mean stress on the rocks declines and 

permeability increases. Thermoelastic and lithostatic confining stresses decline while 

pressures from fluids and gases in pore spaces remain constant. The individual grains of 

the rock matrix contract, the external confining stresses decrease, and fractures develop 

along the grain boundaries. Remobilization of fluids (gas, water) begins—with gas 

expanding to fill developing pore space—and increasing its saturation with respect to 

water. 

This process continues until the strains can no longer be accommodated within the matrix 

structure and macro fracturing begins. The pore throats expand throughout this process. 

Gas, both as free gas in pores and sorbed gas in coals and organic shales, expands to fill 

the voids. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 20 
 

When relative permeability conditions for flow are satisfied the substances previously 

trapped in the pore spaces begin to migrate. It is likely that gas moves first and most 

easily (as compressible gas expands to fill any increased porosity) while increasing its 

saturation at the expense of the water. This initiates gravity segregation, which generally 

leaves the original waters from deposition in place. As the uplift process continues, 

shrinkage of matrix grains reduces net confining stress and increases permeability. 

Basin uplift cycles are most often driven by tectonic activity. The lateral accommodation 

required during this process typically involves faulting. Displacements from basement 

faulting will propagate upwards through the basin fill and disrupt its vertical integrity,

allowing some migration of fluids across unit boundaries, leading to localized migration 

of formation water. Depending on the timing, water composition, temperature, and 

pressure conditions, mobility of waters across bed boundaries potentially alters the 

mineral stability fields, potentially enabling development of secondary porosity, as 

diagrammatically shown in fig. IV-9. 

 Fig. IV-9. Influence of lateral stress 

Application of differential lateral stress during the development process imparts a weak 

planar fabric on the reservoir sediments perpendicular to the paleo-principal horizontal 

stress. Following relaxation of the lateral stress the planar surfaces open and support 

further enhancement of permeability. Extension fractures may develop in high strain 

zones parallel to axial trends of anticlines. Permeability development may be irregularly 

distributed according to the reservoir mineralogy, lithology and strain history of the local 

area. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 21 
 

The macro-stratigraphic architecture of the depositional systems remains intact unless 

disrupted by faulting. Interbedded or overlying ductile shales remain intact and function 

as lateral or vertical permeability barriers. Interbedded coals and organic-rich shales may 

also store hydrocarbons and eventually release gas as reservoir pressures decline. The 

exact contribution of interbedded organic-rich shales and coals to reservoir storage and 

flow is poorly understood possibly underestimated. The uplift process; improves 

permeability for tight gas reservoirs, preserves seals and releases charge. 

With sufficient cooling, pore pressure, and lithostatic stress release, lithologically 

controlled bed scale extensional failure in the reservoir unit is induced, forming macro 

fractures. With sufficient uplift (and associated strain), the brittle reservoir may develop a 

large-aperture, saturated, extensional fracture system. The onset of macro fracturing 

increases total permeability within the reservoir and further facilitates gravity segregation 

of the gas and water. 

Large-scale uplift events are typically associated with faulting of the basement. Late 

stage basement faulting will propagate upwards through the sedimentary section, 

disrupting lateral continuity of sediments with varying scales of shear fractures, and 

further facilitating gravity segregation of gas and water. These fault-related shear fracture 

systems in reservoirs can create areas of high permeability. If they coincide with high gas 

saturation, they produce gas at high rates. Likewise, if fractures coincide with areas of 

high water saturation, they can produce large volumes of water at high rates. Water will 

move through open natural fractures of any type or size when saturation conditions for 

flow are met.

Summary

The outcomes of the burial-uplift reservoir development run the gamut of structural, 

stratigraphic, and relative-permeability controlled, reservoir-trapping configurations. 

Depending on their stage of reservoir and trap development, these configurations show a 

variety of characteristics. Many are dual permeability, dual (and sometimes triple) 

porosity systems with some degree of gravity segregation. Uncovering the full range of 

potential commercial reservoir settings may require tools and concepts that shift away 

from conventional and historical analogs. 

We envision the development of a tight gas reservoir as a process involving multiple 

simultaneous process threads. The process threads are inter-related and often involve 

irreversible changes to the chemical and physical structure of the basin fill. As a 

consequence, alterations to the basin fill in response to the subsidence process are not 

simply reversed on uplift. Rather, basin fill develops different features thru different 

alteration mechanisms. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 22 
 

V. Wild Rose Field Demonstration 

Overview 

The purpose of the field demonstration was to apply our working conceptual model, for 

reducing unwanted water production, in a practical setting. The team performed a 

thorough reservoir characterization and simulation of the field demonstration area to 

establish a base from which water avoidance or remediation strategies could be 

developed. 

Site Selection 

The Wild Rose field matched our profile and was selected for the demonstration because 

the operator (BP) recognized the need to minimize water production for the field while 

maximizing the amount of gas produced. Wild Rose Field is located along the Wamsutter 

arch area of the Washakie basin to the west of the Echo Springs/Standard Draw field 

complex (fig. V-1). The operator contributed the following data for study: well logs, 3D 

seismic, production data and water chemistry data. In addition, a number of new water 

samples were collected. 

Fig. V-1. Wild Rose Field demonstration location map 

The Geologic Characterization of the Field Demonstration Area

The reservoir characterization followed routine practice for construction of a reservoir 

model. The reservoir units were mapped using locally correlative electric log (elog) 

markers. Available core and log data was integrated petrophysically to generate reservoir 

porosity and saturations. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 23 
 

The 3D seismic data was mapped at the Almond (primary reservoir interval) and at a 

prominent deep reflector believed to be near the Paleozoic level. Mapping of reservoir 

units and 3D seismic was completed using the Petra software package. 

The Petra project files with data (no seismic) and grids are included in Appendix E. 

Water samples from wells not previously sampled were collected and analyzed. 

Completion information and production data for the area was acquired, edited for quality 

and sequenced in time for the simulation. 

Fig. V-2 is a general stratigraphic column for Wyoming. 

Modified from Roehler (1990) 

Fig. V-2. Stratigraphic column for Upper Cretaceous in Washakie basin, Wyoming 

Contract DE-FC26-02NT41437 December 2005 Final Report page 24 
 

An Almond type log summarizing depositional environments and regional water 

salinities is shown in fig. V-3. 

Fig. V-3. Wild Rose type log 

The primary reservoir unit is the Almond formation of the Mesaverde Group. It is 

composed of stacked, laterally discontinuous marine and estuarine sandstones 

interbedded with coals, siltstones and shales. In general, individual sandstones are thin

(1-20 feet), coarsening upward sequences. Local channels do occur, and are cleaner, 

higher quality reservoirs. 

There is a prominent flooding surface within the Almond formation (ALMD_SH2) that 

spans the study area. Above the Almond is the Lewis formation, a marine shale/siltstone 

sequence that forms the top seal of the reservoir interval. The upper part of the sequence 

(L-Marker) is high gamma ray “hot” bentonite shale—a prominent stratigraphic marker 

and seismic horizon. Below the Almond formation is the Ericson formation. Cleaner, 

more porous fluvial channel sandstones characterize the Ericson formation. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 25 
 

Regionally, north to south trending Upper Almond retrograde marine barrier island facies 

produce large volumes of gas in fields such as Echo Springs/Standard Draw. Wild Rose 

field lies to the west of the Standard Draw barrier island facies, thus the bulk of the 

field’s production is from stacked thin marine, estuarine and channel facies of the Lower 

and Upper Almond back bar facies (fig. V-4). 

Fig. V-4. Local Wild Rose field index map

Contract DE-FC26-02NT41437 December 2005 Final Report page 26 
 

The Almond was broken into eight lithostratigraphic units (fig. V-5) based upon local 

flooding surfaces (shales) and correlative coal beds. The reservoir interval was then 

subdivided into 23 flow units for petrophysical characterization and simulation. 

Flow unit picks match ARI stratigraphic picks except where subdivided. 

Fig. V-5. Flow unit and stratigraphic pick relationships 

These units were further defined as flow units for petrophysical study and put into the 

reservoir simulation model as displayed in fig. V-4. The ALMD_SH2 is a regional 

flooding surface and can be correlated with some confidence across the demonstration 

area. Other markers are less continuous, as are individual sandstones between the marine 

flooding events. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 27 
 

An upper Almond structure map was constructed using seismic and well control. The 

Almond strikes northwest to southeast across the study area and dips gently to the 

southwest (fig. V-6). 

Map contour interval is 50 feet. Total depth change across the township is approximately 1,100 

feet. Changes in the Almond strike are construed to represent small scale (+/- 50 ft) faulting at the 

reservoir level. 

Fig. V-6. Top Almond subsea structure from 3D seismic and wells 

Local strike changes, some abrupt, occur as the result of warping and small scale faulting 

that trends northeast-southwest across the township. The map constructed at the 

Paleozoic level from 3D seismic is considerably more complex with a clear northeastsouthwest trending fault system bifurcating in the northeast portion of the study area. 

Breccias, vertical stylolites, extension fractures and other evidence of strain are 

commonly observed in Almond cores throughout the Wamsutter area. 

The small scale faulting and changes in strike observed at the Almond level are 

interpreted to reflect the displacements across the basement faults. Stratigraphic 

complexity and low seismic frequency content, however, precluded detailed three 

dimensional fault interpretations within the Almond itself. 

A prominent high-energy reflector, inferred to be near the Paleozoic, is displaced across a 

complex northeast-southwest trending fault system at around 20,000 feet subsurface 

(14,000 feet subsea). There are observable strike changes reflecting numerous smaller 

displacement subparallel faults distributed across the township (fig. V-8). 

Contract DE-FC26-02NT41437 December 2005 Final Report page 28 
 

The prominent deep (possibly Paleozoic) reflector was mapped in detail for the 

demonstration area (fig. V-7). 

Basement-driven 

Fault Zone 

Almond 

Deep Reflector

Fig. V-7 Northwest-southeast seismic time section 

Contract DE-FC26-02NT41437 December 2005 Final Report page 29 
 

The Paleozoic structure was selected for mapping because of its potential to affect the 

distribution of natural fracture permeability within the Almond reservoir. Depth-wise 

there was sufficient displacement across the faults to determine the three-dimensional 

geometry of the fault system. 

The faults dip predominantly southeast and show reverse displacement. The system

bifurcates in the northeast corner of the demonstration area. A subset of faults, located to 

the southeast of the juncture, show northwest dip and reverse displacement (fig. V-8). 

These faults lie immediately beneath the small closed Paleozoic structure in sections 23-

24 (fig. V-8), and at the Almond level of the prominent southwest plunging antiform in 

the same sections. This movement at depth propagates upward, resulting in flexure and 

small scale faulting at the Almond interval and forms the prominent southwest plunging 

antiform at this level. 

Fig. V-8. Paleozoic Depth Structure from 3D seismic 

Contract DE-FC26-02NT41437 December 2005 Final Report page 30 
 

The deep Paleozoic fault system was exposed as a complex of over twenty anastomosing 

reverse faults (the wireframe in fig. V-9). 

In this wireframe illustration of the deep fault system the wireframe elements reflect their relative 

depth in the subsurface, blue (deeper) to red (shallower). North is to the top of the screen capture 

and the area is the same as the depth structure maps of the Almond and Paleozoic horizons

previously referenced. 

Fig. V-9. Wireframe illustration of deep Paleozoic fault system 

Contract DE-FC26-02NT41437 December 2005 Final Report page 31 
 

Petrophysical Reservoir Characterization 

Particular attention and care was paid to the determination of reservoir properties from 

the well logs and core available, both inside the demonstration area and from the greater 

Wamsutter area. Our working concept suggested permeability and relative permeability 

would be key issues in the field demonstration. 

A variety of approaches, techniques and calculation methods were scrutinized in order to 

derive a solid petrophysical model for determining saturation. The petrophysical aspects 

of the demonstration are summarized here and discussed in detail in Appendix E. 

The primary tasks of the petrophysical reservoir characterization were: 

• Build a petrophysical model for clay volume, porosity, permeability, and water 

saturation based on openhole log suites and core data. 

- Review prior petrophysics and revise/incorporate as appropriate. 

• Calibrate cased-hole pulsed neutron log response (TDT) to the petrophysical 

models developed for the openhole logs. 

• Correct core data to in situ reservoir pressure conditions and shift, relative to logs. 

• Utilize log suites to distinguish between gas and low salinity formation water. 

• Define and distribute flow units based on stratigraphy, facies and petrophysical 

characteristics. 

• Export and incorporate summations into a reservoir simulation model. 

A total of 103 wells were loaded and screened for petrophysics. Seventy-one had 

openhole logs, and thirty-seven had cased hole logs. Of this 108, five had both cased and 

openhole logs. Eleven of the 103 wells were cored. Of the 103 wells, eighty-five were 

fully processed for petrophysics; the remaining wells had cased hole logs with limited or 

poor data sets. Production logging information was limited to one well within the 

demonstration area. 

Present wellbore mechanical designs and operating practice precluded acquisition of 

additional logs during the project. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 32 
 

Rw Calibration 

Produced water analyses were used to calibrate the petrophysical interpretation. Accurate 

in situ Rw values are critical to effective pay determination. Resistivity values from

samples collected indicate a prominent high Rw anomaly in the southwest portion of the 

demonstration area, immediately overlying the trace of the major basement fault 

(fig. V-10). 

This map shows the average resistivity of the produced water samples (measured at 68 deg F) in 

the Wild Rose demonstration area. H indicates areas of high Rw and L indicates areas of lower 

Rw. There is a conspicuous high resistivity anomaly in sections 28, 29, 32, 33 and 34 that is most 

likely related to faulting. 

Fig. V-10. Produced water Rw map of Wild Rose field demonstration area 

Historical analyses were particularly valuable in this effort because they were typically 

collected from specific intervals within the Almond as opposed to the present-day 

practice of commingling the entire Almond section. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 33 
 

Spontaneous potential (SP) and resistivity ratio techniques were used to calibrate Rw, 

which as a reality check were then tested via Pickett plot methods (fig. V-11). 

Using Rw=0.46@68F, Pickett plots show the gas-bearing intervals to calculate 25-60% water 

saturation. 

Fig. V-11. Pickett plot gas zone – Rw =0.46 @ 68F 

Some limited special core analysis data was available to support the saturation validity. 

Complete details and examples of this work are in Appendix E. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 34 
 

Vertically and laterally shifting Rw values make pay determination a challenge in this 

area. Combining the Rw and pay determination techniques led to the identification of an 

apparent salinity interface that appears to delineate the boundary between discontinuous 

gas charged sands of the Almond and underlying sands with lower gas saturation (fig. V12) although it neither follows structure rigorously nor appears to be flat. 

Gas-water boundary follows dipping structure, but not rigorously; therefore, is a 

boundary between discontinuous gas-charged & aquifer sands rather than an actual 

contact. 

Fig. V-12. Inferred SP-GWC structure map 

Despite mineralogical and textural complexity, a high-quality petrophysical model 

(Appendix E) for Vclay, porosity, permeability and water saturation was developed and 

applied. It works well in most openhole logs and in approximately 60% of the cased hole 

logs but requires extensive quality control. Permeability was found to be affected by both 

porosity and Vclay. 

The conclusion that SP and resistivity ratios can be used effectively to determine changes 

in formation water (Rw) is a valuable, immediately applicable outgrowth of this 

demonstration. Although the theory and techniques themselves are old, they have not 

been applied of late because of the difficulties in calibration against Rw. Improved 

understanding of Rw brought about by this project may make the techniques valuable 

tools in pay determination and water avoidance. 

The results of the structural mapping and petrophysical study were broken down into 

flow units, gridded across the demonstration area and sampled on a regular grid node 

basis for incorporation into the reservoir simulation input files. Initially, a natural fracture 

permeability grid was generated using Discrete Fracture Network (DFN) techniques and 

integrated into the permeability grids for each layer. There was no local fracture data with 

which to calibrate the network; however, and subsequent permeability adjustments 

Contract DE-FC26-02NT41437 December 2005 Final Report page 35 
 

(increases) required to achieve an effective history match across the field were 

sufficiently extreme as to make the DFN permeability approach irrelevant. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 36 
 

The Reservoir Simulation 

Reservoir simulation technology was used to link the petrophysical reservoir 

characterization with the actual production behavior of the field. This was done to 

identify relationships between water production and reservoir characterization that could 

be used to minimize water production during continuing development. Historical gas and 

water production data, completion intervals, gathering pressures, and other engineering 

data were compiled into simulator files together with the earth science and petrophysical 

interpretations. 

Matching Procedures 

Appendix includes a detailed discussion of the matching procedures as well as input and 

output simulator files with a CometTM post processor for displaying them. 

To perform this modeling work, the township study area was discretized into a 40- by 40-

foor rectangular grid of 800-foot by 800-foot squares. This grid spacing covered the 

complete 23,000-acre demonstration area. Vertically, the model contained twenty-three 

layers of alternating gas and water-charged sand and coal layers, with each layer having 

variable thicknesses, spatially (fig. V-13). 

Fig. V-13. Cross-section from east to west along northern portion of model grid

There were twelve sand layers and eleven coal layers, with odd-number layers being sand 

bodies (from top to bottom in the reservoir column). When constructing these alternating 

sand/coal layers, only immediate sand/coal pairs were permitted to communicate 

vertically. This procedure emulated the rather interspersed nature of coal stringers 

through the Almond formation. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 37 
 

Consistent with field completion practices no coal seams were perforated in the model. 

Sands were completed in accordance with industry-reported data. 

With nearly twenty-eight years of historical production data available for the Wild Rose 

area, wells were controlled through monthly gas rates. Field-observed backpressures were 

a secondary operational constraint. Changes in operating practice and regulations over the 

years contributed uncertainty to the history match. Additional dynamic production data 

(e.g., detailed wellhead flowing or gathering pressures, additional production logs, etc.) 

could have strengthened the history match. 

A reservoir model representing the Wild Rose demonstration area was built, executed and 

adjusted until we achieved a reasonable match between reservoir attributes and 

production. The petrophysically derived reservoir parameters were held constant through 

the match process. No additional information indicated a need to revisit the petrophysics 

and the underlying data was considered more reliable than other model inputs. 

Permeability was used as the primary attribute for adjustment. Initial coarse areal 

adjustments were made, progressing to individual wells near the conclusion of the match 

process. Original gas-in-place volumes, as calculated in the simulator, are shown in Table 

V-1. 

Table V-1. Initial gas & water in place for 23 model layers 

Contract DE-FC26-02NT41437 December 2005 Final Report page 38 
 

Overall, 1.1 tcf of gas and 820-billion barrels of water were estimated to be in-place in 

the study area (Table V-1). Noting that sand and coal (odd and even layers, respectively) 

bodies alternate within the model, nearly 60% of the original hydrocarbons in-place were 

estimated to have been contained in the sands, leaving the remaining 480 bcf in the 

adsorbed state within the coal seams. Field verification of the employed isotherm should 

be conducted to confirm the accuracy of the estimated gas in-place in the coal seams. 

Field Match Results 

While the field match was quite good, individual well matches did vary; however, these 

variabilities were considered acceptable within the overall field match. Table V-2 shows 

the by-layer production during the twenty-three year history. 

Table V-2. By-layer voidage & cumulative gas recovered in field thru October 2003 

Contract DE-FC26-02NT41437 December 2005 Final Report page 39 
 

It is noteworthy that the coal seams are negligible contributors to date, while the sands 

have produced only 5% of their initial volume and 3% of the overall system in-place

volume. Depletion in this system, via pressure for sand layer 15, is depicted in fig. V-14. 

Fig. V-14. Initial to final gas pressure arrays (layer 15) depicting some edge effects & showing 

relative depletion for inter-grid wells 

Contract DE-FC26-02NT41437 December 2005 Final Report page 40 
 

The Wild Rose area history match results supported the following suppositions. 

1. There appears to be infill potential in this area because of the low volumes

produced to date. The operators are currently undertaking infill projects. 

(Eleven of seventy-nine permitted wells had been drilled as of 9/05). 

2. Taking away edge effects, average well drainage appears to be eighty acres in 

the developed areas and interference appears to be minimal (fig. V-15). 

Therefore, the infill pattern development is justified. 

3. The coal seams apparently have not contributed to the overall production. 

Confirmation of coal initial gas-in-place (IGIP) is necessary to better gauge 

the future contribution of these seams.

The field-wide cumulative gas and water production matches are shown in fig. V-15. 

Fig. V-15. Final field-wide cumulative gas & water production 

ARI experience during this production simulation is in stark contrast to the assertion of 

Shanley, et al (2004) that little correction was usually required to match bulk production 

permeabilities to values generated using core and petrophysical methods. It is clear from

fig. V-16 that major upward adjustments to permeability were required to match the 

historical production rates. Only twelve of the well bore cells required less than a twofold adjustment between original matrix kh and that required to match production. The 

average adjustment was 7.5-fold and the maximum was 36-fold. For this reason a major 

reassessment of the permeability model was made in order to generate a more 

geologically reasonable permeability map across the demonstration area. Fig. V-16 is a 

comparison between the original and matched arrays for one of the layers. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 41 
 

Fig. V-16. Permeability arrays before and after modifications (layer 15) 

Contract DE-FC26-02NT41437 December 2005 Final Report page 42 
 

Forecast Model 

The permeability matrix for the forecast model was generated using the original matrix 

values (petrophysically derived) and conditional simulation methods. The composite, 

matched permeability array was deconstructed and the matrix permeability values were 

subtracted. The wellbore cells alone were geostatistically described using variography. 

A conditional simulation was run using the wellbore cells and the eight surrounding cells 

as inputs. The permeability matrix was repopulated using the nine cells around each 

wellbore as givens and populating the intervening areas from the simulation array. The 

resulting fracture permeability array was added back to the matrix arrays and reintegrated into the simulation file. 

In this way, the local wellbore match values were held constant and the inter-well areas 

received statistically valid values that reflected the range of the control data set. The final 

layer 15 permeability array is shown in fig. V-17 as an example. 

This map is the permeability grid (of layer 15) used for the forecast runs. The variography 

indicated a significant nugget effect and directional anisotropy in a northeast-southwest trend. 

Fig. V-17. Final layer 15 forecast permeability grid 

Contract DE-FC26-02NT41437 December 2005 Final Report page 43 
 

The Wild Rose area production forecast used the existing seventy-six wells as a base. 

Additionally, the eleven wells drilled and completed during the demonstration were postappraised against the forecast. Sixty-eight permitted well locations were projected to be 

drilled at a rate of two per month going forward and then added to the forecast. 

The forecast run was executed for twenty-five additional years, through 2028. See fig. 

V-18 for the gas rate and cumulative gas forecasts for the 155 well-run as compared to 

forecasting only the pre-existing seventy-six wells already matched in the base case. This 

forecast estimates that peak gas rate will be on the order of 35 MMcfd and further 

suggests that cumulative gas production from the area will eventually surpass 200 bcf 

(projected to the year 2035). 

The cumulative gas production from the eleven new wells compared favorably to the 

forecast, suggesting the history match should be adequate to predict aggregate infill 

potential as well as estimate future production. However, point forward the forecast 

model should be updated on an ongoing basis to reflect the data gathered (via geophysical 

logs and production) and minimize the differences between the forecast and actual field 

performance. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 44 
 

Fig. V-18. Gas rate (A) & cumulative gas (B) forecasts for 155 wells, compared to forecasting 

pre-existing 76 wells 

Contract DE-FC26-02NT41437 December 2005 Final Report page 45 
 

Analysis 

The simulation results were reviewed to identify any observable relationships between 

bulk permeability and water production. A data set of seventy-five current wells with 

over 12 months production was selected for reasons of completion and operating 

consistency. Total matrix permeability-thickness (kh) was subtracted from the simulation 

(match) kh. This difference is attributed to the permeability contribution of natural 

fractures. 

The wells were ranked 1/low through 75/high in (1) matrix kh, (2) natural fracture kh, (3) 

first 12 months gas production and (4) water gas ratio. A four-variable bubble plot (fig. 

V-19) was constructed using the resulting relative rankings. 

Best 

Wells

Normalized Gas 

Productivity Rank

Matrix kh Rank

Natural Fracture 

kh Rank

Fig. V-19. Four-variable plot of Wild Rose reservoir attributes 

This plot (fig. V-19) shows clearly that the highest productivity gas wells with the 

smallest water gas ratio are those with the most matrix kh and the most fracture kh (small 

bubbles (upper right back corner of the cube). 

Contract DE-FC26-02NT41437 December 2005 Final Report page 46 
 

The size of the bubbles represents the water-gas ratio ranking (smaller is better). The 

matrix kh, fracture kh and normalized gas variables are plotted against the axes (z, x and 

y respectively). The origin (0,0,0) is located at the lower left front corner of the cube. The 

upper right back corner of the cube is 80, 80, 80 and represents the highest-ranking wells 

for each variable within the population. A point located at the lower front corner of the 

plot would exhibit the worst matrix kh, greatest fracture kh component and worst gas 

production. 

The upper back corner represents the best matrix kh, worst fracture kh component and the 

best production rank. There are no points in the upper back corner. 

The majority of the wells with relatively small fracture permeability components also 

rank lower in normalized gas production (near the axis between 0,0,0 and 80,0,0), with a 

mixture of water-gas ratio rankings. There is also a significant number of low 

productivity, high fracture component wells with high water production (large bubbles, 

low in the cube, towards the right. 

The simulation results from the Wild Rose area demonstrate that the Almond reservoir is 

a composite system of both matrix and natural fracture permeabilities. Wells optimally 

located to access significant pore volume and fracture permeability structurally high in a 

gas column will flow significant gas at low water to gas ratios. Wells with little fracture

permeability component tend to be poor producers of gas although they may generate less 

water as well. 

This relationship of gas to water is also observed with high fracture permeability wells, 

which tend to produce at high water gas ratios. Thus the impact of natural fracture 

permeability on production quality is neither all good nor all bad. Rather, the negative or 

positive impact of natural fracture permeability on production is determined by its 

relative position within the gas column—high or low. 

Trends and Context 

Understanding the nature and occurrence of water in tight gas settings is more a question 

of understanding trends and context than specific determinative criteria. There are several 

significant, related trends in the Wild Rose demonstration area. 

Salinity Trends 

For example, a variation in water salinities (high to low) should be expected between the 

marine upper Almond, transitional middle Almond, and lower Almond/Ericson. A 

consistent Rw across these intervals would be anomalous. Successful pay determination 

in these situations requires rigorous data collection to capture changing salinity trends 

because individual data points have little value out of context. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 47 
 

Fig. V-8 is a map of produced water resistivity in the demonstration area showing a major 

Rw anomaly in the southwest portion of the township. Strontium isotopes and calcite 

saturation indices were anomalous as well (elucidated in Appendix C). Water has moved 

in this area on the basis of the geochemical signatures. 

Basement Structural Trends 

Structure mapping at the deep Paleozoic level confirmed a prominent fault trend 

extending from the southwest corner of the township to the northeast corner (fig. V-7). 

There is an analogous trend in the Almond structure (fig. V-7). 

The inflection of the prominent flexure at the Almond level is subparallel to, and nearly 

overlies, the deep fault itself. The first-year water production map shows a less prominent 

but nonetheless visible alignment along the same trend (fig. V-21). The high permeability 

cells from the reservoir simulation display similar directional trends (fig. V-17). 

Fig. V-21. Wild Rose field—first year water production 

Contract DE-FC26-02NT41437 December 2005 Final Report page 48 
 

Structural Modeling 

To analyze the impact of the deep Laramide displacements on the reservoir horizon we 

constructed a geomechanical model of the deep basement fault system (fig. V-7). From 

the model we created a map of estimated shear stress at the Almond level (fig. V-22). 

Structure contours at the Almond level are shown superimposed on shear 

stress, estimated from boundary element modeling of the deep Paleozoic fault system. The open 

circles represent fracture permeability rank (larger is better). Only the central NE-SW fault system 

was modeled, resulting in the NW and SE quarters of the township containing no valid stress 

values. The purple area (dark center area) represents maximum concentration of shear stresses

along fault trend at Almond level. 

Fig. V-22. Projected Laramide shear stresses at Almond level 

Not surprisingly, the distribution of the simulated shear stresses generally follows the 

northeast southwest corridor delineated by the water production and simulator 

permeabilities. 

Structural geometries, water production, and simulator match permeabilities all support a 

northeast-southwest structural grain across the demonstration area. Time slices of the 

confidential seismic data and small deflections of the structure contours indicate the 

presence of small scale, small displacement shear zones traversing the demonstration area 

along the general corridor of the simulated shear stress maxima. At least one source of 

unwanted water production in this area is related to subseismic (resolution) fault systems. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 49 
 

Vertical Mineralogical Trend 

Another aspect of the Wild Rose demonstration area is a vertical mineralogical trend. Yin 

and Surdam (1994) characterized Almond and Ericson sandstones petrographically and 

mineralogically from cores taken around the GGRB. They found the Almond to be 

significantly more feldspar rich than the Ericson. Two-direction whole core permeability 

data (presented in Appendix D) demonstrates the extreme sensitivity of the Ericson core 

to stress release microfracturing versus other units, including the Almond. 

In the Wild Rose area, the sandstone maturity (increasing quartz content) improves 

downward through the Almond intervals to the Ericson. Permeability is likely to parallel 

this trend, increasing with depth. Traditionally this was considered a positive but as the 

saturation calculations from the petrophysics study show, gas saturation decreases with 

depth, particularly below the more significant coal units. An increasing permeability 

trend in the face of decreasing gas saturation may not be desirable if the objective is to

avoid water production. 

Production Validation 

The operator ran only one production log for the Wild Rose demonstration area. A simple 

log montage of this production log, a TDT log, and the mudlog was constructed and is 

available in Appendix F. Water-gas ratios for the fluid gas influx at each perforation are 

shown in Table V-3. 

Table V-3. Water-gas ratios for fluid gas influx at each of 9 perforation sets 

Perforation Set Depth Water Rate (Bbls/d) Gas Rate 

(Mcfd)

Water-Gas Ratio 

1 9550 0 12 0.000

2 9600 1.8 121 0.015

3 9640 19.8 1463 0.014

4 9690 12.8 81 0.158

5 9730 2.7 20 0.135

6 9750 1.1 15 0.073

7 9790 0 6 0.000

8 9830 0 2 0.000

9 >9900 4.6 31.7 0.145

Contract DE-FC26-02NT41437 December 2005 Final Report page 50 
 

Nine intervals were perforated across approximately 400 feet of the Almond reservoir. 

Three out of nine perforated intervals in this well flow at a water gas ratio ten-fold higher 

than the other six. Perforation sets 4, 5,and 9 produce less than 10% of the gas and nearly 

50% of the water. Perforation sets 1, 2 and 3 yield 91% of the gas and 50% of the water. 

Visual examination of the TDT log (log panel in Appendix F) does not suggest major 

differences in sand quality across the interval yet a single perforation zone makes four 

times the gas rate as all other zones combined at only a tenth of the water-gas ratio of the 

lower zones. 

Our petrophysical study projected the salinity/gas-water boundary (GWB) interface to be 

at approximately 9,800-feet MD in this well. Based on that projection, the lower zone at 

9,900 feet is most likely a low-gas saturation, quartz-rich, high-permeability lower 

Almond sand. The low-gas rate, low-water ratio zones 7 and 8 reflect tight, low 

permeability reservoir rock and zones 4, 5 and 6 are transitional, with permeability to 

both gas and water. Zone 3 has a conspicuously high flow rate but low water gas ratio. It 

most likely represents a natural fracture zone. Zones 1 and 2 are low permeability zones 

high in the gas column, right beneath the Lewis Shale. 

Lack of openhole logs precludes solid confirmation of this production scenario. It does 

display potential interpretations upon which a water avoidance strategy based on 

selective completion could be built and executed within an operational program. A 

consistent data collection policy would enable such strategies to be implemented. 

Water Remediation Strategies 

In the demonstration area simulation unwanted water was produced when higher 

permeability intervals were encountered and perforated in zones with low gas saturation. 

We found no pervasive irreducible gas saturation settings within the Wild Rose area that 

uniformly produce gas at low water-gas ratios. This was indicated by the presence of a 

generally identifiable salinity boundary that coincides with increased gas saturations in 

the upper few hundred feet of the Almond formation. 

This salinity boundary does not correspond directly to structure. On openhole electric 

logs this boundary presented as a saline SP log deflection. (For other indicators see 

Appendix E, Petrophysical section.) With additional calibration, the boundary may be 

identifiable on TDT logs. Thus, in new wells the boundaries should be identified and 

completion operations planned accordingly. 

To understand the salinity boundary with respect to stratigraphy, formation waters will be 

routinely sampled during completion operations. Periodic flow tests prior to hydraulic 

fracture completion operations may yield fluids for Rw analysis. This will improve 

petrophysical pay determinations and reduce completion of highly permeable, low gas 

saturation zones. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 51 
 

Quartz and calcite rich reservoir intervals are particularly susceptible to developing 

permeability to water. The large thermal expansion coefficients of quartz and calcite 

contribute to the development of large aperture grain-bounding microfractures during 

uplift. Large pore throats create low capillary entry pressures and increase mobility of

fluids. 

Quartz content of Mesaverde sediments peaks in the delta plain fluvial facies (lower 

Almond channels and Ericson formation). These units are also more likely to contain 

relatively fresh formation water, complicating gas saturation determinations. Based on 

the results presented here, these units are at high-risk of low-gas saturation coupled with 

high permeability to water. 

To avoid completion of high permeability, low gas saturation zones in these intervals, we 

recommend perforation followed by flow testing. While not specifically investigated 

here, we hypothesize that these units also have lower internal stresses that could cause 

hydraulic fractures to propagate towards them. Even a modest program of stress 

determination and hydraulic fracture mapping, early in a development program, could 

avoid or ameliorate such issues. 

Unwanted water production from natural fracture zones occurring low in a low-saturation 

gas zone is another significant menace identified during this study. These zones are 

identifiable by their extremely high permeabilities. We advocate two strategies for 

managing this setting: (1) avoidance or (2) capture. 

Avoidance Strategy for Small Scale Faulting 

Our proposed strategy for avoiding small scale faulting is to identify and avoid them prior 

to drilling. Throughout the Wild Rose demonstration area there are small-scale fault 

zones at or below the effective resolution of seismic. We believe the primary producing 

perforation in the Wamsutter Rim 15-2 (discussed earlier) is such a zone. Typically these 

fault zones are highly permeable, and when optimally located within the gas column, 

very prolific gas producers. However, when located in a transitional or low gas saturation 

zone they can be a significant economic drag on the well. 

An attempt was made during this project to construct detailed fault maps within the 

Almond reservoir interval. Stratigraphic complexity and low seismic frequency content 

were major barriers to successfully completing this effort. The Colorado School of Mines 

Reservoir Characterization Project (RCP) has demonstrated the use of an automated 

fault-picking software package (Ant Tracker AlgorithmTM, Schlumberger) for interpreting

small-scale faults within reservoir volumes (supplemented with human editing). In the 

future such a semi-automated process might be an effective tool in finding and avoiding 

small-scale fault zones. Seismic resolution will likely remain a challenge because 

velocity or other issues may preclude the level of accuracy required to intersect or avoid a 

50-foot discontinuity at 10,000 feet subsurface. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 52 
 

Capture Strategy for Small Scale Faulting 

A second strategy to address the issue is to capture the permeability fabric of the 

unanticipated small scale fault. Most natural small-scale faults contact significantly more 

reservoir than man-made hydraulic fractures. If this were not the case hydraulic fractures 

would consistently perform much better, and more consistently. 

Significant downspacing of an area substantially increases the subsurface sampling. Thus 

downspacing offers the opportunity to perform detailed subsurface mapping if 

appropriate information and logs are obtained and analyzed. While there were no image 

logs available for this study, our experience suggests consistent image log collection 

during the downspacing program offers the opportunity to map fracture zones directly, 

developing detailed maps of their geometry. 

Highly detailed fault maps would enable the deliberate intersection of these extremely 

permeable zones at the optimal point in the reservoir. While is it projected that the rate of

return could increase, an economic analysis of each location would substantiate the value. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 53 
 

CONCLUSION 

Oil and gas exploration and development are progressive processes that are hugely 

dependent on historical data and experience for successful results. Data pertaining to the 

chemical and electrical properties of intra-formational waters is also crucial but has been 

difficult to effectively access. This is no longer the case as a primary output of this 

project is a robust database amassing thousands of formation water analyses. 

Digital Database and Atlas 

The digital database provides data with dynamic value for operators to increase gas 

production from key Rocky Mountain basins, without significant additional overhead. 

Along with electric logs, core, and seismic, the database becomes yet another valuable 

tool for maximizing production. 

A digital atlas showing the distribution of the data and some specific analyses has been 

constructed using ArcReader to increase the usability of the database. The digital atlas 

has query and limited mapping capability for users without ready access to Geographic 

Information Systems (GIS) software. 

Applications 

Beyond the database however, this project has demonstrated techniques of interpretation 

and applications of the formation water data to identify and solve common exploration 

and production (E&P) issues. The tools, techniques and strategies presented here have 

potential for impacting secondary porosity prediction, formation evaluation, and 

development strategies. 

1. Secondary Porosity Prediction 

Formation water geochemistry is an indicator of the in situ diagenetic system. The 

chemical compositions of subsurface waters can be interpreted within the context of their 

host sediments to reveal anomalies of potential significance. For example, local 

variations in ion saturation indices can reflect inter-formational water movement with 

significant implications for secondary porosity development. 

2. Formation Evaluation 

Vertical and lateral formation water resistivity changes are common. Collecting water 

samples for Rw and using the information in log interpretation will improve pay 

determination and completion decisions. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 54 
 

Bulk system permeabilities are often underestimated. Bulk reservoir permeabilities 

determined through reservoir simulation can be many times greater than those initially 

estimated through petrophysical studies alone. (Bottom hole build up pressure tests also 

show bulk reservoir permeabilities, but were not within the scope of this project.) 

3. Development Strategies 

Perforation Strategy 

Avoid completion of high permeability low gas saturation zones. In higher risk intervals, 

we recommend perforation followed by flow testing. While not specifically investigated 

here, we hypothesize that these units also have lower internal stresses that could cause 

hydraulic fractures to propagate toward the high-permeability unit. Even a modest 

program of stress determination and hydraulic fracture mapping, early in a development 

program, could avoid or mitigate such issues. 

Avoidance Strategy for Small Scale Faulting 

Identify and avoid small-scale faults prior to drilling. Throughout most tight gas 

reservoirs there are small-scale fault zones at or below the effective resolution of seismic. 

We believe the primary producing perforation in the Wamsutter Rim 15-2 (discussed 

earlier) is such a zone. Typically these fault zones are highly permeable, and when 

optimally located within the gas column, very prolific gas producers. However, when 

located in a transitional or low gas saturation zone they can be a significant economic 

drag on the well. In the future semi-automated fault-picking processes might be an 

effective tool in finding and avoiding small-scale fault zones. 

Capture Strategy for Small-Scale Faulting 

Capture the dynamic value of the drilling program. Most natural small-scale faults 

contact considerably more reservoir than man-made hydraulic fractures. Significant 

downspacing of an area substantially increases the subsurface sampling. Thus 

downspacing offers the opportunity to perform detailed subsurface mapping. Consistent 

image log collection during the downspacing program allows for identifying fracture 

zones directly, and developing detailed maps of their geometry. This would enable the 

deliberate intersection of these extremely permeable zones at the optimal point in the 

reservoir. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 55 
 

Future Research 

A key result of this project is an integrative conceptual gas reservoir development model.

This model encompasses diverse views within a single developmental continuum. 

Effective tight gas reservoir development is the result of a dynamic process with multiple 

essential ingredients: 

- The original sedimentary provenance 

- The proper mix of depositional systems and facies 

- A strong history of burial and uplift

It follows from the conceptual model that: 

Generation of increasing reservoir permeability is a natural by-product of stress release 

during uplift. Gas sweet spots form in traps delineated by strain fields or ductility 

contrasts. Understanding the natural process of sweet spot development—by stress 

release and concentration of gas in traps formed by strain fields and/or ductility 

contrasts—offers options for manmade replication through engineering technologies. 

A prime example is cavitation, used commonly in coalbed methane plays and less 

commonly in conventional reservoirs to increase permeability around a wellbore (1999 

Palmer). During cavitation completions, a large volume of rock material is removed from

the reservoir creating a cavity or void space. The cavity accentuates the normal 

disturbance of the local in situ stress field created by the wellbore. Under favorable 

conditions shear failure occurs in the rocks surrounding the cavity and fractures 

propagate away from the wellbore into the reservoir. The shear fractures improve 

production by creating permeability conduits and increasing the effective wellbore radius. 

By creating room for expansion of the rocks themselves, the cavitation technique might 

also initiate stress release and associated permeability increases in the rocks surrounding 

the well. Speculation suggests development of the cavity should parallel the natural 

process of permeability enhancement during uplift and allow the gas and water to selfsegregate. Developing the practical methods of deliberately inducing such events in tight 

gas sands will require additional research. 

The uplifted gas basins of the Rocky Mountains have large volumes of gas trapped in 

low-saturation, low-permeability settings, outside established field areas. Where 

hydraulic fracturing techniques improve connection to a reservoir, effective application 

of cavitation (or similar) techniques may not only improve connectivity they may actually 

increase local permeability in the reservoir and release trapped gas. 

Developing the technology to proactively create the conditions for increased permeability 

of these reservoirs and allowing the gas to segregate itself in situ and flow into the 

wellbore for recovery would capture the full dynamic value of the large resource base and 

should be considered a long term research goal. 

Contract DE-FC26-02NT41437 December 2005 Final Report page 56 
 

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ACRONYMS AND ABBREVIATIONS 

ACRONYMS AND ABBREVIATIONS 

ALMD_SH2 ... Almond formation 

API ................ American Petroleum Institute 

ARI ................ Advanced Resources Inc. 

Bbl................. barrel 

bcf ................. billion cubic feet 

BHPBU.......... bulk wellbore scale production permeabilities 

BVW_F.......... bulk volume water = SWT_F * PHIE_F 

bwpd.............. barrels of water per day 

CAL_BS ........ caliper-bit size difference 

CEC............... cation exchange capacity 

CEC1............. CEC calculation from porosity 

COAL_FLG ... coal flag 

COALFLGT ... TDT coal flag

CTE............... coefficient of thermal expansion 

DFN............... discrete fracture network 

DST............... drill stem test 

elog ............... electric log 

EHS............... effective horizontal stress 

EVS............... effective vertical stress 

E&P............... exploration and production 

fm .................. formation 

GGRB............ Greater Green River Basin 

Contract DE-FC26-02NT41437 December 2005 Final Report page 97 
 

GIP................ gas-in-place

GIS................ Geographic Information Systems 

GRL............... gamma ray linear 

GRN1 ............ normalized gamma ray 

GWB.............. gas-water boundary 

IGIP............... initial gas-in-place 

k .................... permeability 

kh .................. permeability-feet 

K_PHI_HI ...... high core porosity-permeability trend

K_PHI_LO..... low core porosity-permeability trend

K_PHI_MD .... medium core porosity-permeability trend 

K_PHI_VC..... permeability from modified Timur-Coates equation (PHI & Vclay) 

MD................. measured depth 

md ................. millidarcies 

md/pu ............ millidarcies/porosity unit

MMcfd ........... millions of cubic feet per day 

MWX ............. multi-well experiment 

nms ............... net mean stress 

NPHILS ......... NPHI in limestone units 

NPHISS......... NPHI in sandstone units 

OGIP ............. original gas in place 

ohm-m........... ohm meters

phi ................. porosity 

PHIE.............. effective density porosity 

PHIE_D1 ....... PHIT_D1 * (1-Vclay) 

PHIE_DF....... final effective density porosity (edited for clay, coal & washouts) 

PHIE_DG1 .... PHIT_DG1 * (1-Vclay) 

Contract DE-FC26-02NT41437 December 2005 Final Report page 98 
 

PHIE_F.......... final effective porosity 

PHIE_ND1..... PHIT_ND1 * (1-Vclay) 

PHIE_NDF .... final effective density porosity (edited for clay, coal & washouts) 

PHIE_PN3..... final corrected TDT porosity 

PHIT_AVG .... average of PHIT_MX and PHIT_VSH 

PHIT_D1 ....... total density porosity, grain density = 2.68g/cc 

PHIT_DG1..... total density porosity with variable grain density and SXO gas correction

PHIT_MX....... maximum porosity based on Vshale-Porosity trend 

PHIT_ND1..... total neutron-density crossplot porosity 

PHIT_ND2..... total porosity form sum of squares of NPHI and DPHI 

PHIT_VSH..... porosity derived from Vshale-porosity trend 

ppm ............... parts per million 

PRES1 .......... pressure curve 

psi.................. pounds per square inch

QC................. quality control 

Qv.................. cation exchange concentration 

QV1............... Qv calculation from CEC & porosity 

RCP............... Reservoir Characterization Project 

RES_FLG1.... reservoir flag 

RHOBS ......... environmentally corrected & shifted density 

RHOMAT....... density of matrix by stratigraphic interval 

Ro.................. vitrinite reflectance in oil 

RTratDS ........ ratio of deep/shallow resistivity 

RTratSD ........ ratio of shallow/deep resistivity 

Rw................. formation water resistivity 

RW_Rmf1...... resistivity of mud filtrate 

SEM .............. scanning electronic microscope 

Contract DE-FC26-02NT41437 December 2005 Final Report page 99 
 

SP ................. spontaneous potential (log) 

SPE............... Society of Petroleum Engineers 

SQL............... structured query language 

Sw ................. water saturation 

SW_ARC1..... Archie water saturation in Almond gas zone (1.0, 1.74, 2.00, 0.46 @ 68F) 

SW_ARC2..... Archie water saturation in Almond Aquifer (1.0, 1.74, 2.00, 1.74 @ 68F) 

SW_ARC3..... Archie water saturation in Erickson (1.0, 2.00, 2.00, 1.74 @ 68F) 

SW_DWT1 .... water saturation from dual water equation 

SW_SIM1...... water saturation from Simandoux equation 

SW_WS2....... water saturation from Waxman-Smits equation 

SWT_F.......... final merged water saturation 

Sxo................ water zone saturation 

SXO_ARC1... Archie water saturation for using RW_Rmf & shallow resistivity 

tcf .................. trillion cubic feet 

TD ................. total depth 

TDS............... total dissolved solids 

TDT ............... thermal decay time 

TDT_RT ........ TDT resistivity derived from the sigma curve 

TDTratFN ...... ratio of TDT far/near counts 

TDTratNF ...... ratio of TDT near/far counts 

TEMP1 .......... temperature Curve 

TGRN............ TDT normalized gamma ray 

TPHI.............. cased hole pulsed neutron porosity 

TSW_WS1 .... TDT water saturation from Waxman-Smits equation 

TVD............... true vertical depth 

USGS............ United States Geological Survey

VCLSTB ........ volume clay by Steiber method 

Contract DE-FC26-02NT41437 December 2005 Final Report page 100 
 

Vr................... vitrinite reflectance 

VSH............... volume shale 

VSHGRL ....... volume shale by gamma ray linear method 

WRB.............. Wind River Basin 

Contract DE-FC26-02NT41437 December 2005 Final Report page 101 
 

Contract DE-FC26-02NT41437 December 2005 Final Report page 102 

APPENDICES 

A. Database 

• Database_Readme

• Database_Access

• Database_CSV

• Database_DBF

• Database_XLS

B. Atlas of Maps 

• ArcReader Install

• Digital Atlas

C. Produced Water Geochemistry

D. Working Model for Reservoir Development 

E. Wild Rose Field Petrophysics

F. Wild Rose Reservoir Simulation